1. Field of the Invention
The present invention relates generally to the downhole delivery of superheated steam for recovering crude oil of low specific gravity, for enhancing reservoir drive, and for deparrafinization. More particularly, the invention relates to enhanced oil recovery methods and apparatus for subterraneously steam with a heat capacity consistent with 900 degrees F. of superheat, i.e., steam at a minimum temperature of 900 degrees F. above the saturation temperature of a water/steam mixture, at a pressure sufficient to overcome the frictional pressure losses associated with the downhole piping surface roughness, the steam mass flow rate, and the downhole inside geometric parameters that exist from the top side surface to the steam piping outlet at the bottom of the well bore, concurrently with normal oil extraction processes that function through separate production tubing.
2. Description of the Related Art
It has long been recognized in the art that, when the natural drive energy of an oil reservoir or well decreases over time, it becomes increasingly difficult to raise oil to the surface. As pressure decreases over time, secondary and tertiary methods are used to bring oil to the well bore where it may be retrieved. Artificial lift at the well bore will be required to achieve sufficient production. Various artificial lift processes are commonly used to increase reservoir pressure and to force oil to the surface at some time during the production life of a well.
The two most common methods of inducing of artificial lift in wells are broadly referred to as “pumping” and “gas injection”. Beam pumping engages equipment above and below ground to increase pressure and push oil to the surface. Beam pumps, consisting of a sucker rod string and a sucker rod pump, are exemplified by the common, black-colored jack pumps employed by onshore oil wells that create suction to lift the oil.
Above the surface, the beam pumping system rocks back and forth, reciprocating a string of sucker rods, which plunge down into the well bore. The sucker rods are connected to the sucker rod pump, which is installed as a part of the tubing string near the bottom of the well. The beam pumping system rocks back and forth to operate the rod string, sucker rod and sucker rod pump. The sucker rod pump lifts the oil from the reservoir through the well to the surface. Artificial lift pumping can also be accomplished with a downhole hydraulic pump, rather than sucker rods, or with electric submersible pump systems deployed at the bottom of the tubing string. An electric cable runs the length of the depth of the well.
Artificial lift systems can employ gas injection to reestablish pressure, making a well produce. Injected gases or vapors reduce the pressure on the bottom of the well by decreasing the viscosity of the fluids in the well. This, in turn, encourages the fluids to flow more easily to the surface. Typically, the gas that is injected is recycled with fluids produced from the well.
Gas lift is the optimal choice for offshore applications. Occurring downhole, the compressed gas is injected down the casing tubing annulus, entering the well at numerous entry points called gas-lift valves. As the gas enters the tubing at these different stages, it forms bubbles, lightens the fluids/and lowers the pressure.
It is well known in the art to inject high temperature steam within wells to decrease the viscosity of heavy crude oils, facilitating subsequent pumping and recovery. The temperature of the injected steam must be at or above the saturation temperature at a given injection pressure. Injected steam warms the well bore, heating the piping, the casings, and the surrounding environment. Injected steam must not only be of sufficient temperature and pressure to properly liquefy targeted crude oil within the well, but a sufficient volume of such steam is required during the injection process for success. In general, in the prior art, large volume demands mitigate against the successful operational maintenance of the requisite applied steam temperature.
Steam generators for supplying superheated steam are known in the art. For example, U.S. Pat. No. 4,408,116 issued to Turner on Oct. 4, 1983 discloses a superheated steam generator with dual heating stages. A more recent steam generator design is illustrated in our prior patent U.S. Pat. No. 8,359.919 issued Jan. 22, 2013 and entitled “Super Heated Steam Generator With Slack Accommodating Heating Tanks,” that is owned by the same assignee as in this case.
There are currently several different forms of steam injection technology for oil recovery. The two primary prior art methods are “Cyclic Steam Stimulation” and “Steam Flooding.” The “Cyclic Steam Stimulation” method, also known as the “Huff and Puff” method, consists of injection, soaking, and production stages. Steam is first injected to heat the oil in the reservoir to raise the temperature and lower the oil viscosity, thereby enhancing fluid flow. Injected steam may be left in the well for periods of time for soaking and diffusion of the steam into the well environment. Subsequently, oil is extracted from the treated well, at first by natural flow (since the steam injection will have increased the reservoir pressure) and then by artificial lift. Production decreases as the oil/steam mixture cools, necessitating repetition of the steam injection steps. The “huff and puff” method thus injects steam in periodic cycles, applying periodic “puffs” of steam between periodic soaking periods, during which the steam generator apparatus recharges and accumulates another volume of steam for subsequent injection. The “huff and puff” process is most effective in the first few steam cycles. However, it is typically only able to recover approximately 20% of the Original Oil in Place (OOIP), compared to steam flooding, which has been reported to recover over 50% of OOIP.
Steam flooding involves multiple wells. Some wells are used as steam injection wells, and others are used for oil production. Two mechanisms are at work to improve the amount of oil recovered. The first is to heat the oil to higher temperatures and to thereby decrease its viscosity so that it flows more easily through the formation toward the producing wells. A second mechanism is the physical displacement of oil in a manner similar to water flooding, in which oil is meant to be pushed to the production wells. While more steam is needed for this method than for cyclic steam simulation methods, it is typically more effective at recovering a larger portion of the oil.
A form of steam flooding termed “steam assisted gravity drainage”, abbreviated “SAGD,” utilizes multiple, spaced apart, horizontal wells. Steam is injected into the upper SAGD well in an effort to reduce the viscosity of the oil deposits to the point where gravity will pull the oil into the producing well.
However, it has become evident to us that, for maximum crude oil recovery efficiency, superheated steam can be injected concurrently with the extraction operation in a single well. In this manner, time delays are avoided, and additional energy is available through the large number of degrees of superheat (defined as the difference between the actual steam temperature and the saturation temperature at the delivery pressure). Thus the requirement of supplemental wells is obviated.